PIPELINES & DOWNSTREAM Alyeska cyber-aware

12
US crude approaches 11 million bpd in April; $65 Brent 2nd qtr average page 3 l PIPELINES & DOWNSTREAM l NATURAL GAS Vol. 26, No. 20 www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of May 16, 2021 • $2.50 l EXPLORATION & PRODUCTION see OIL PRICES page 12 see ANGOON TIDAL page 11 Company applies to FERC for Angoon tidal power evaluation Littoral Power Systems Inc. has applied to the Federal Energy Regulatory Commission for a preliminary permit for a tidal power project at Kootznahoo Inlet near Angoon on Admiralty Island in Southeast Alaska. This is one of two preliminary tidal power permit applications in Alaska that FERC is considering — this small project and a much larger one in Cook Inlet. A preliminary permit, if issued, grants the permit holder prior- ity to file a license application during the permit term. Littoral Power Systems, LPS, said the preliminary permit would allow it to “evaluate the potential for generating electricity from tidal energy in Kootznahoo Inlet in Angoon, Alaska.” Hummingbird nesting season stops TMX pipeline expansion Canada’s Trans Mountain pipeline expansion has never escaped the battlefront from the time of the project’s public launch in 2012. Building a 710-mile link to triple capacity on the system to 890,000 barrels per day of crude bitumen from the Alberta oil sands, through the Canadian Rockies to a Vancouver area tanker terminal, primarily for export to Asian markets was never going to be easy. As opposition to what is known as TMX has stretched the completion date for the C$12.6 billion undertaking to late 2022, environmentalists, First Nations and all-purpose protesters have drawn strength from their occasional success in stalling work on the pipeline. see PIPELINE EXPANSION page 10 see DRILLING RULES page 9 Oil prices hit 8-week high May 12; Q3, Q4 demand acceleration seen Alaska North Slope crude rose 37 cents to close at $67.85 per barrel May 12, while West Texas International rose 80 cents to close at $66.08 and Brent rose 77 cents to close at $69.32. It was the highest close for WTI since March 5, and the high- est close for Brent since March 11. In early trading, Brent once again made a run at $70, rising to $69.79 before dropping later in the day as Colonial Pipeline restarted its 5,500-mile fuel line from Texas to the East Coast after a precautionary shutdown spurred by a cyberattack discov- ered May 7. U.S. Energy Secretary Jennifer Granholm said in a May 11 briefing that it would “take days” after the restart for the line to be “up and running.” “This pipeline has never been shut down before,” she said. Alyeska cyber-aware TAPS secure, but operator has close eye on Colonial Pipeline cyber attack By STEVE SUTHERLIN Petroleum News A lyeska Pipeline Service Co. maintains a state of readiness when it comes to cyberthreats. Just like any other operating risk of running the 800-mile Trans Alaska Pipeline System, cyber risk is on the front burner 24/7 at Alyeska, according to Michelle Egan, Alyeska chief communications officer. “We have a very comprehensive cybersecurity program here — it involves multiple layers of protec- tion; we have an in-house cybersecurity team; we have a number of third-party experts and vendors that we work with; and we have very regular engagement with law enforcement agencies around this area — so that we’re aware of what is happening in the world of cyber security, Egan told Petroleum News in a May 11 interview. The operator of TAPS is watching closely the sit- uation at Colonial Pipeline Co. where a 5,500-mile fuel pipeline was shut down by a cyber-attack discov- ered May 7, choking off vital fossil fuel supplies to Borealis moves forward Independent continues permitting 2022 Nanushuk exploratory drilling program By KAY CASHMAN Petroleum News I n preparation for exploratory drilling next winter in its Castle North prospect in the northeastern National Petroleum Reserve-Alaska, Borealis Alaska Oil Inc. applied for an Oil Discharge Prevention and Contingency Plan with the Alaska Department of Environmental Conservation. That plan, which is compre- hensive and covers the company’s explo- ration drilling operations for all its NPR-A North Slope oil and gas prospects, is out for a 30-day public review that ends June 7 at 11:59 p.m. AKT. In NPR-A, the Borealis leases lie in what the Anchorage-based independent named the Castle prospect trend, a series of six individual Brookian prospects in the lower Nanushuk formation. Southwest of Willow, the prospects are directly analogous to the geo- logic setting for major oil discoveries at Pikka, under development by Oil Search (Alaska), and by ConocoPhillips at Willow, Richard “Dick” Garrard, Borealis chief technical officer, told Petroleum News in mid-2020. Borealis’ Castle East prospect lies in the same sand body as the Harpoon prospect, where ConocoPhillips drilled an exploration well in the winter of 2019-20. Borealis is looking for a joint venture partner for BP underpins Woodfibre Doubles take from planned LNG project; First Nations splinter group gets BC cash By GARY PARK Petroleum News C anada’s often-overlooked Woodfibre LNG project has received a large helping hand from BP which has now signed a second deal to take output from the proposed export plant near Vancouver. Woodfibre said it will sell 750,000 metric tons a year to BP Gas Marketing over 15 years, dou- bling BP’s total off-take to 1.5 million mt from the planned initial plant capacity of 2.1 million mt. The deal is seen as an important advance for the C$1.8 billion project as sets a final investment decision in the third quarter by its owner, Pacific Oil & Gas. A Woodfibre spokeswoman said the company is now seeking contracts for the remaining 29% of annual capacity but will not make those deals a mandatory element of its decision to proceed with construction. She said Woodfibre is engaged in final engi- neering work while attempting to revise its envi- ronmental permit to allow floating accommodation for up to 600 workers during construction. see CYBER-AWARE page 10 see BOREALIS PERMITTING page 8 see WOODFIBRE LNG page 11 “We learn things and change things because that’s part of this world of cybersecurity, it’s continually moving … a very dynamic area.” —Michelle Egan, Alyeska chief communications officer RICHARD “DICK” GARRARD On the positive side, global LNG demand has increased every year since 2012, propelled by fast-rising demand in Asia. Moriarty: Interior scraps Trump’s new Arctic safety, enviro updates In the current administration’s “eager- ness” to do away with Trump’s policies, politics have dictated what should be a scientific process, Kara Moriarty told Petroleum News regarding the U.S. Interior Department May 7 decision not to pursue the former administration’s pro- posal for changes in Arctic drilling rules offshore Alaska. A May 7 statement from Interior said existing regulations released by the Obama administration in 2016 remain in effect and “are critical KARA MORIARTY

Transcript of PIPELINES & DOWNSTREAM Alyeska cyber-aware

Page 1: PIPELINES & DOWNSTREAM Alyeska cyber-aware

US crude approaches 11 million bpd in April; $65 Brent 2nd qtr average

page

3

l P I P E L I N E S & D O W N S T R E A M

l N A T U R A L G A S

Vol. 26, No. 20 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of May 16, 2021 • $2.50

l E X P L O R A T I O N & P R O D U C T I O N

see OIL PRICES page 12

see ANGOON TIDAL page 11

Company applies to FERC for Angoon tidal power evaluation

Littoral Power Systems Inc. has applied to the Federal Energy

Regulatory Commission for a preliminary permit for a tidal

power project at Kootznahoo Inlet near Angoon on Admiralty

Island in Southeast Alaska.

This is one of two preliminary tidal power permit applications

in Alaska that FERC is considering — this small project and a

much larger one in Cook Inlet.

A preliminary permit, if issued, grants the permit holder prior-

ity to file a license application during the permit term.

Littoral Power Systems, LPS, said the preliminary permit

would allow it to “evaluate the potential for generating electricity

from tidal energy in Kootznahoo Inlet in Angoon, Alaska.”

Hummingbird nesting season stops TMX pipeline expansion

Canada’s Trans Mountain pipeline expansion has never

escaped the battlefront from the time of the project’s public

launch in 2012.

Building a 710-mile link to triple capacity on the system to

890,000 barrels per day of crude bitumen from the Alberta oil

sands, through the Canadian Rockies to a Vancouver area tanker

terminal, primarily for export to Asian markets was never going

to be easy.

As opposition to what is known as TMX has stretched the

completion date for the C$12.6 billion undertaking to late 2022,

environmentalists, First Nations and all-purpose protesters have

drawn strength from their occasional success in stalling work on

the pipeline.

see PIPELINE EXPANSION page 10

see DRILLING RULES page 9

Oil prices hit 8-week high May 12; Q3, Q4 demand acceleration seen

Alaska North Slope crude rose 37 cents to close at $67.85 per

barrel May 12, while West Texas International rose 80 cents to

close at $66.08 and Brent rose 77 cents to close at $69.32.

It was the highest close for WTI since March 5, and the high-

est close for Brent since March 11.

In early trading, Brent once again made a run at $70, rising to

$69.79 before dropping later in the day as Colonial Pipeline

restarted its 5,500-mile fuel line from Texas to the East Coast

after a precautionary shutdown spurred by a cyberattack discov-

ered May 7.

U.S. Energy Secretary Jennifer Granholm said in a May 11

briefing that it would “take days” after the restart for the line to

be “up and running.”

“This pipeline has never been shut down before,” she said.

Alyeska cyber-aware TAPS secure, but operator has close eye on Colonial Pipeline cyber attack

By STEVE SUTHERLIN Petroleum News

Alyeska Pipeline Service Co. maintains a state of

readiness when it comes to cyberthreats.

Just like any other operating risk of running the

800-mile Trans Alaska Pipeline System, cyber risk

is on the front burner 24/7 at Alyeska, according to

Michelle Egan, Alyeska chief communications

officer.

“We have a very comprehensive cybersecurity

program here — it involves multiple layers of protec-

tion; we have an in-house cybersecurity team; we

have a number of third-party experts and vendors that

we work with; and we have very regular engagement

with law enforcement agencies around this area — so

that we’re aware of what is happening in the world of

cyber security, Egan told Petroleum News in a May

11 interview.

The operator of TAPS is watching closely the sit-

uation at Colonial Pipeline Co. where a 5,500-mile

fuel pipeline was shut down by a cyber-attack discov-

ered May 7, choking off vital fossil fuel supplies to

Borealis moves forward Independent continues permitting 2022 Nanushuk exploratory drilling program

By KAY CASHMAN Petroleum News

In preparation for exploratory drilling

next winter in its Castle North prospect

in the northeastern National Petroleum

Reserve-Alaska, Borealis Alaska Oil Inc.

applied for an Oil Discharge Prevention

and Contingency Plan with the Alaska

Department of Environmental

Conservation. That plan, which is compre-

hensive and covers the company’s explo-

ration drilling operations for all its NPR-A North

Slope oil and gas prospects, is out for a 30-day public

review that ends June 7 at 11:59 p.m. AKT.

In NPR-A, the Borealis leases lie in what the

Anchorage-based independent named the Castle

prospect trend, a series of six individual

Brookian prospects in the lower Nanushuk

formation. Southwest of Willow, the

prospects are directly analogous to the geo-

logic setting for major oil discoveries at

Pikka, under development by Oil Search

(Alaska), and by ConocoPhillips at Willow,

Richard “Dick” Garrard, Borealis chief

technical officer, told Petroleum News in

mid-2020.

Borealis’ Castle East prospect lies in the

same sand body as the Harpoon prospect,

where ConocoPhillips drilled an exploration well in

the winter of 2019-20.

Borealis is looking for a joint venture partner for

BP underpins Woodfibre Doubles take from planned LNG project; First Nations splinter group gets BC cash

By GARY PARK Petroleum News

Canada’s often-overlooked Woodfibre LNG

project has received a large helping hand

from BP which has now signed a second deal to

take output from the proposed export plant near

Vancouver.

Woodfibre said it will sell 750,000 metric tons

a year to BP Gas Marketing over 15 years, dou-

bling BP’s total off-take to 1.5 million mt from the

planned initial plant capacity of 2.1 million mt.

The deal is seen as an important advance for the

C$1.8 billion project as sets a final investment

decision in the third quarter by its owner, Pacific

Oil & Gas.

A Woodfibre spokeswoman said the company is

now seeking contracts for the remaining 29% of

annual capacity but will not make those deals a

mandatory element of its decision to proceed with

construction.

She said Woodfibre is engaged in final engi-

neering work while attempting to revise its envi-

ronmental permit to allow floating accommodation

for up to 600 workers during construction.

see CYBER-AWARE page 10

see BOREALIS PERMITTING page 8

see WOODFIBRE LNG page 11

“We learn things and change things because that’s part of this world of

cybersecurity, it’s continually moving … a very dynamic area.” —Michelle Egan, Alyeska chief communications officer

RICHARD “DICK” GARRARD

On the positive side, global LNG demand has increased every year since 2012,

propelled by fast-rising demand in Asia.

Moriarty: Interior scraps Trump’s new Arctic safety, enviro updates

In the current administration’s “eager-

ness” to do away with Trump’s policies,

politics have dictated what should be a

scientific process, Kara Moriarty told

Petroleum News regarding the U.S.

Interior Department May 7 decision not to

pursue the former administration’s pro-

posal for changes in Arctic drilling rules

offshore Alaska.

A May 7 statement from Interior said

existing regulations released by the

Obama administration in 2016 remain in effect and “are critical

KARA MORIARTY

Page 2: PIPELINES & DOWNSTREAM Alyeska cyber-aware

2 PETROLEUM NEWS • WEEK OF MAY 16, 2021

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Petroleum News Alaska’s source for oil and gas newscontentsAlyeska cyber-aware TAPS secure, but operator has close eye on latest cyber attack

Borealis moves forward Continues permitting 2022 Nanushuk exploratory drilling program

BP underpins Woodfibre Doubles take from LNG project; First Nations group gets BC cash

ON THE COVER

Oil prices hit 8-week high May 12; Q3, Q4 demand acceleration seen

Moriarty: Interior scraps Trump’s new Arctic safety, enviro updatesCompany applies to FERC for Angoon tidal power evaluationHummingbird nesting season stops TMX pipeline expansion

EXPLORERS 2021 PREVIEW4 ConocoPhillips: ‘hitting reset’ in 2021

Alaska’s most consistent explorer resumes activities at several projects; 700 people on GMT-2 project’s third winter of work

3 US crude almost 11 million bpd in April

EIA expects Brent to average $65 per barrel in 2nd quarter, $61 in 2nd half of year and in 2022, with WTI above $55 through 2022

2 Division approves Prudhoe ops amendments

8 Weekly US rotary rig count up by 8 to 448

FINANCE & ECONOMY

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l E X P L O R A T I O N & P R O D U C T I O N

Division approves Prudhoe ops amendments By KRISTEN NELSON

Petroleum News

The Alaska Division of Oil and Gas has approved

requests from Hilcorp North Slope for three projects

as amendments to the Prudhoe Bay unit operations plan.

The most recent, dated May 10, is for authorization to

construct a temporary polymer injection facility at W Pad

at Prudhoe. The purpose is to inject polymer in W Pad

wells to increase production. W Pad is some 17 miles

northwest of Deadhorse.

The division said the temporary facility will consist of

several modules to be placed centrally on the pad. The

temporary facility is estimated to be in place for about

one year, with the project planned to start in June and

conclude by December.

Included in the plan are:

•Leveling the existing pad to prepare for module

installation;

•Place rig mats and insulation to support skids;

•Installing a water let down module, 20 feet by 8 feet;

•Installing a polymer hydration module 40 feet by 8

feet;

•Installing a polymer injection pump module 40 feet

by 8 feet;

•Installing a polymer loading and storage module 40

feet by 8 feet:

•Installing some 2,500 feet of 2-inch polymer injection

piping on existing pipe racks; and

•Tying modules to existing aboveground facilities

including power and water.

Pigging shelter Also at W Pad at Prudhoe, the division on May 6

approved a request to install a pig shelter, a 32- by 20-foot

shelter on a steel frame over existing pipelines on the

western side of the pad.

The division said the purpose is to provide a shelter for

pig-launching operations on W Pad, with the project

expected to begin June 1 and be completed by December.

Plan activities include:

•Installing steel foundation bracing and VersaTube

framing;

•Constructing the 32- by 20-foot pigging shelter;

•Installing associating piping and values; and

•Installing a safety guardrail.

In the first quarter of the year, W Pad accounted for

some 4% of Prudhoe crude oil production, up from 3.2%

in the first quarter of 2018.

Main Construction Camp On May 6 the division approved a Hilcorp request to

see PRUDHOE OPS page 3

Page 3: PIPELINES & DOWNSTREAM Alyeska cyber-aware

By KRISTEN NELSON Petroleum News

In its May Short-Term Energy Outlook,

issued May 11, the U.S. Energy

Information Administration said U.S. crude

oil production continues to rise.

While the most recent data, for February,

shows a drop, to 9.9 million barrels per day,

down 1.2 million bpd from January, EIA

said it believes that is an anomaly.

The agency is estimating that U.S. crude

production rose to 10.9 million bpd in

March and to almost 11 million bpd in

April.

The February decline was caused by

cold temperatures, EIA said, which caused

significant declines in Texas production and

smaller declines in other states, with pro-

duction outages estimated to be largely lim-

ited to February.

The agency expects the West Texas

Intermediate price will stay in a range to

encourage drilling.

“We estimate that U.S. benchmark West

Texas Intermediate crude oil prices will

remain above $55 per barrel through 2022,”

EIA Acting Administrator Steve Nalley said

in a statement. “This benchmark price will

likely encourage producers to drill and

complete wells and to offset production

declines at existing wells, and that activity

along with our forecast for rising produc-

tion from multiple new projects in the

Federal Offshore Gulf of Mexico, leads us

to believe U.S. crude oil production will

average 11.3 million barrels per day in the

fourth quarter of 2021 and 11.8 million bar-

rels per day in 2022.”

EIA said the spread between Brent and

WTI has been increasing since November,

with weather events in the U.S. appearing to

play a role along with rising U.S. crude oil

production. From a narrow average spread

of $1.68 per barrel in October, the lowest

point since the pandemic began, the spread

has widened each month, averaging $3.38

per barrel in March and $3.63 per barrel in

April.

Brent steady Brent prices averaged $65 per barrel in

April, EIA said,

unchanged from the

March average.

“Brent crude oil

prices remained at

$65 per barrel in

April as COVID-19

continued to affect

demand in major

economies,” Nalley

said. “U.S. oil

demand is increasing along with COVID-

19 vaccination rates and overall econom-

ic activity, but India’s oil demand is

declining due to rising COVID-19 cases,”

he said.

The agency is forecasting that Brent

will average $65 per barrel in the second

quarter, $61 per barrel in the second half

of the year and $61 per barrel in 2022.

World consumption EIA said it estimates that worldwide

96.2 million bpd of petroleum and liquid

fuels were consumed in April, up 15.8

million bpd from April 2020 but down 4

million bpd from 2019 levels.

Nalley said EIA has lowered its esti-

mates for global consumption based on

“lower economic growth estimates and

decreased demand for transportation fuels

in India.” Global consumption for 2021 is

now estimated to average 97.7 million

bpd, he said, “an increase of 5.4 million

barrels per day over 2020.”

EIA said the estimate for global petro-

leum and liquid fuels consumption is an

average of 101.4 million bpd in 2022, an

increase of 3.7 million bpd.

Natural gas The Henry Hub spot price for natural

gas averaged $2.66 per million British

thermal units in April, up slightly from a

March average of $2.62 per million Btu,

EIA said. The price is expected to average

$2.78 per million Btu in the second quar-

ter, and $3.05 for the year, up from the

2020 average of $2.03 per million Btu.

Two factors are expected to drive the

rise in natural gas prices, the agency said

— growth in liquefied natural gas exports

and rising domestic consumption in the

residential, commercial and industrial

sectors.

The Henry Hub spot price is expected

to fall to an average of $3.02 per million

Btu in 2022, with LNG exports expected

to slow and production expected to rise.

“U.S. liquefied natural gas exports set

an all-time record in March 2021,”

Nalley said, “averaging 10.5 billion cubic

feet per day, followed by an April average

of 9.2 billion cubic feet per day, the most

liquefied natural gas exported from the

United States during April since the

United States began exporting liquefied

natural gas.”

EIA said that in 2020 and January

2021, “more than half of U.S. LNG

exports went to Asia. However, in

February and March 2021, more than half

of U.S. LNG exports went to Europe as a

result of spot natural gas prices in Europe

reaching levels similar to spot natural gas

prices in Asia.”

The agency said it expects LNG

exports to decline in May to 8.6 bcf per

day before rising above 9 bcf per day in

the summer months to meet peak

demand, with exports expected to aver-

age 9.2 bcf per day in both 2021 and

2022, up from 6.5 bcf in 2020, with flat

exports in 2022 reflecting the agency’s

expectation “that limited new expert

capacity will come online during the fore-

cast period.”

U.S. consumption of natural gas is

expected to average 82.6 bcf per day this

year, down 0.7% from 2020, declining in

the forecast to 82.5 bcf per day in 2021,

with the decline attributed, in part, to

electric power generators switching to

coal as a result of rising natural gas

prices.

Outside the power sector, consump-

tion is expected to rise due to expanding

economic activity and colder tempera-

tures in 2021 compared to 2020.

More electricity from renewables “Our forecast increase in electricity

generation from renewable sources is

especially pronounced in Texas, where

we expect renewables to generate about

30% more electricity this summer than

last summer,” Nalley said.

EIA said planned additions to U.S.

PETROLEUM NEWS • WEEK OF MAY 16, 2021 3

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Regulations are changing constantly. For the most up-to-date inform

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install a new aboveground water

tank at the Main Construction Camp

at Prudhoe. The division said the

existing water tank subsided over

time and is no longer suitable as the

main tank for the MCC fire suppres-

sion system.

The new site will be excavated

and a foundation constructed to hold

the tank, which will be tied in to the

existing tank. The existing tank will

remain in place and minimal

changes will be required in the pip-

ing layout. Work is expected to start

in June and be complete by the end

of the year, the division said.

Plan activities include:

•Constructing the foundation for

the new tank; and

•Installing the new 370,000-gal-

lon water tank. l

continued from page 2

PRUDHOE OPS

l F I N A N C E & E C O N O M Y

US crude almost 11 million bpd in April EIA expects Brent to average $65 per barrel in 2nd quarter, $61 in 2nd half of year and in 2022, with WTI above $55 through 2022

STEVE NALLEY

see EIA OUTLOOK page 7

Page 4: PIPELINES & DOWNSTREAM Alyeska cyber-aware

By ERIC LIDJI For Petroleum News

ConocoPhillips Alaska Inc. is the most

prolific North Slope explorer of the

21st century.

As many of its large multinational

contemporaries were retreating from

exploration to focus on development,

ConocoPhillips continued to pursue

opportunities beyond its existing North

Slope units. And although many smaller

independents occasionally outdid

ConocoPhillips in any given exploration

season, they have all lacked

ConocoPhillips’ longevity, either leaving

after a few seasons or selling prospects

after de-risking them.

In the 19 years since the 2002 merger

that created ConocoPhillips, the Alaska

unit of the Houston-based multinational

exploration and production company has

diligently pushed westward beyond the

Kuparuk River unit. Its exploration activ-

ity has now expanded the reach of North

Slope oil develop-

ment beyond the

Colville River and

into federal lands.

But for a compa-

ny defined by its

constancy and con-

sistency, the past

few years have been

unpredictable. Some

seasons were among

ConocoPhillips’ most active ever. Others

saw no exploration at all. Others started

out strong but then were unexpectedly cut

short.

ConocoPhillips conducted no explo-

ration activities this year, following two

robust winters. In the winter season of

2018-19, the company completed nine

wells listed as “exploratory” by the

Alaska Oil and Gas Conservation

Commission. The list included one well

in the Kuparuk River unit and two wells

within the Colville River unit, in addition

to six traditional exploration wells in the

National Petroleum Reserve-Alaska.

The company planned a seven-well

exploration program for 2020 but only

completed three before reducing its activ-

ities in response to the emerging coron-

avirus pandemic.

This year, the company delayed its

decision to restart drilling activity pend-

ing the results of the Nov. 3 ballot initia-

tive to increase oil production taxes in the

state. Following the defeat of the ballot

measure, and then the stabilization of oil

prices around $40 per barrel,

ConocoPhillips announced plans to

resume drilling before the end of 2020.

The announcement covered a range of

development and maintenance projects at

the Kuparuk River unit, the Colville

River unit and the Greater Mooses Tooth

unit. But it did not include any explo-

ration drilling for the 2020-21 season,

making this year one of only a handful of

exploration seasons over the past 20 years

without ConocoPhillips.

The starts and stops of the past few

years can make it easy to overlook the

larger trend: ConocoPhillips has been

undertaking a notable expansion of its

exploration activities. In addition to its

long-standing movement to the west, it

has also been pursing emerging opportu-

nities closer to its existing units at the

western edge of the central North Slope.

In a presentation at Meet Alaska in late

March 2021, ConocoPhillips Alaska

President Erec Isaacson described 2021

as “hitting reset.” The company would

focus on lowering costs and engaging

stakeholders and would also resume reg-

ular development drilling, as well as

progress on $1.1 billion in projects across

the North Slope: Greater Mooses Tooth

No. 2 construction, Alpine expansion,

Willow permitting, Nuna development

and ongoing work at the Eastern NEWS

(North East West Sak) at the Kuparuk

River unit.

Heading west ConocoPhillips is best known for its

gradual westward expansion on the North

Slope.

Through its predecessor companies,

ConocoPhillips helped discover or devel-

op the Kuparuk River unit, as well as the

Alpine field and its satellites at the

Colville River unit.

After the National Petroleum Reserve-

Alaska was reopened for exploration in

1999, ConocoPhillips’ predecessor

Phillips Petroleum Co. was one of the

first companies to explore the region. In

May 2001, Phillips announced three

major NPR-A discoveries.

“These discoveries mark an important

milestone in the Alaska oil industry,”

then-president of Phillips Alaska Kevin

Meyers said at the time. “Though the

results are preliminary, we’re confident

the discoveries will prove to be of com-

mercial quantities.”

Anyone who follows the announce-

ments of oil and gas companies knows to

be mindful of hyperbole, but

ConocoPhillips has long since justified

those comments. The company has spent

the last 20 years pursuing the NPR-A dis-

coveries announced by its predecessor in

May 2001, and it is only recently seeing

oil production from the first of those

properties.

The current push dates to 2008. That

year, ConocoPhillips formed the Greater

Mooses Tooth unit around the cluster of

NPR-A wells and discoveries west of

Nuiqsut. The move helped protect soon-

to-be-expiring leases dating back to the

original 1999 lease sale.

ConocoPhillips also relinquished 19

federal tracts around Intrepid 2 well south

of Barrow, a sign that it was losing inter-

est in wildcat exploration on the North

Slope.

Between 2008 and 2016,

ConocoPhillips gradually backed away

from Alaska offshore exploration, too.

The company dropped most of its

Beaufort Sea leases in 2009 and spent

several years pursuing Chukchi Sea

opportunities before dropping those leas-

es in 2016.

At the same time, ConocoPhillips was

increasingly focusing its energies on

exploration opportunities within close

reach of its existing onshore infrastruc-

ture. Toward the end of 2015,

ConocoPhillips CEO Ryan Lance

announced, “Over the past couple of

years, we’ve been able to change the pro-

file of our Alaska business. We’ve trans-

formed the declining production base into

one that can deliver stable production for

a decade.”

The U.S. Bureau of Land Management

approved the formation of the Greater

Mooses Tooth unit in 2008.

ConocoPhillips expanded on its May

2001 discoveries in the unit area with a

series of related exploration wells,

including the Pioneer No. 1 and

Grandview No. 1 wells in early 2009 and

the Rendezvous No. 3 and Flat Top No. 1

wells in early 2014.

Through subsequent exploration,

appraisal and development work,

ConocoPhillips unofficially divided

Greater Mooses Tooth into three regions:

east, central and west.

ConocoPhillips began producing the

eastern leases in October 2018, when it

brought the GMT-1 pad online. The com-

pany is currently in the final stages of

development work on the GMT-2 pad,

which will develop the leases in the

southcentral portion of the unit.

The company employed as many as

700 people on the GMT-2 project this

winter, which was the third and final year

of construction on the $1.4 billion proj-

ect. Development drilling on the first of

l E X P L O R E R S M A G A Z I N E P R E V I E W

ConocoPhillips: ‘hitting reset’ in 2021 Alaska’s most consistent explorer resumes activities at several projects; 700 people on GMT-2 project’s third winter of construction

4 PETROLEUM NEWS • WEEK OF MAY 16, 2021

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May 2021

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36 wells was scheduled to begin in the

second quarter with first oil by the end of

the year. GMT-2 should produce 35,000

to 40,000 barrels per day at its peak.

Willow Exploration activity in recent years has

focused on the western leases. Those leas-

es are now associated with the Bear Tooth

unit, which is adjacent to Greater Mooses

Tooth.

ConocoPhillips began staking its first

Tinmiaq wells in late 2015 and completed

a two-well drilling program in the area in

early 2016. The work was notable for

pushing beyond previous drilling activity

in the region. Way back in May 2001,

when Phillips Alaska Inc. announced its

initial oil discoveries in the area, the

exploration activity was clustered in what

would later become the center of the

Greater Mooses Tooth unit. Subsequent

exploration activity pushed to the south

and the east — but not into the western

leases.

The initial Tinmiaq exploration pro-

gram came as ConocoPhillips was sanc-

tioning its initial $900 million GMT-1

development at the eastern end of Greater

Mooses Tooth and permitting its GMT-2

development on leases in the south-cen-

tral section of the unit.

In early 2017, ConocoPhillips

announced that the first Tinmiaq wells —

Tinmiaq No. 2 and Tinmiaq No. 6 — had

made a major discovery in the Nanushuk

formation. The Willow prospect was esti-

mated to contain as much as 300 million

barrels of recoverable oil and could

potentially produce as much as 100,000

barrels per day at its peak.

“This discovery is tremendously excit-

ing not only for ConocoPhillips, but also

for the state of Alaska,” then-

ConocoPhillips Alaska President Joe

Marushack said. “Willow’s proximity to

existing infrastructure improves the eco-

nomic viability of the discovery.

Development of Willow, a potential

multi-billion-dollar investment, could

provide thousands of jobs during con-

struction and could generate substantial

revenue for the federal government, state,

North Slope Borough, and communities

in the NPR-A.”

In addition to being encouraged by

resource estimates, ConocoPhillips was

intrigued by Willow’s geology. Willow

was one of three major North Slope oil

discoveries made within a year in the

Nanushuk formation or in the closely

associated Torok formation — following

Armstrong Energy’s Pikka and Caelus

Energy’s Tulimaniq discoveries.

In late 2016, after drilling the two

Tinmiaq wells but before announcing the

discovery, ConocoPhillips acquired 65

tracts covering 594,972 acres in a federal

lease sale and 74 tracts covering 142,280

acres in a nearby state lease sale. And in

2017, after announcing the discovery,

ConocoPhillips commissioned a 3D seis-

mic survey over the region.

That may seem like a rush of activity,

but subsequent permitting documents

suggested that ConocoPhillips had dis-

covered the Willow prospect in 2002 with

its Hunter A well.

ConocoPhillips returned with a four-

well program in 2018 (Tinmiaq No. 7,

No. 8 and No. 9 and West Willow No. 1)

and a five-well program in 2019 (Tinmiaq

No. 10, No. 11, No. 13, No. 15 and No.

16, along with re-entry projects on

Tinmiaq No. 2 and Tinmiaq No. 9). The

company planned a six-well program in

2020 but was only able to complete two

wells (Tinmiaq No. 18 and No. 20) before

coronavirus restrictions interceded.

One of the big questions hanging over

the Willow prospect from the beginning

was whether ConocoPhillips would

develop it independently or as an Alpine

satellite. The decision would impact the

cost and design of the project, as well as

its production rate.

A satellite would produce about 40%

to 50% of the peak production of a stand-

alone field, and it would be timed to

accommodate the existing Alpine facili-

ties. Production would be drawn out

across a longer timeline. But a satellite

would be the cheaper option.

In a proposed development plan filed

with the U.S. Bureau of Land

Management in early 2018,

ConocoPhillips endorsed a standalone

facility. “The existing processing facility

at Alpine is not feasible for a tie-in of the

Willow development due to geographic

and technical constraints,” the company

wrote. “The Willow master development

plan would require construction of a new

processing facility, the Willow Central

Facility.”

The proposal did, however, envision

using existing pipeline systems to bring

seawater and diesel fuel to the proposed

field and to deliver sales-quality crude

from the field.

The Willow project was delayed earli-

er this year when the U.S. Court of

Appeals for the 9th Circuit extended an

injunction, banning ConocoPhillips from

conducting fieldwork for its Willow oil-

field development. The injunction

emerged from a lawsuit by Sovereign

Inupiat for a Living Arctic and several

environmental organizations against the

Bureau of Land Management. The case

was still pending as The Explorers was

going to print.

Harpoon As work advanced on the Willow

prospect, ConocoPhillips again stepped

westward.

The company’s initial plans for the

2019-20 winter exploration season

included exploration drilling at the

Harpoon prospect, southwest of Willow.

Before the program began, Executive

Vice President of Exploration and

Production Matt Fox said that seismic

work had identified an anomaly worth

investigating. It “looks like there could be

… quite substantial resources,” he said.

“Now it could be gas and it could be

water. It’s almost certainly a reservoir,

because we’re pretty sure that’s what the

seismic signature’s telling us … but it

doesn’t have to be huge for it to be a

tieback to the Willow hub.”

The season was supposed to be among

the largest ever for ConocoPhillips. In

addition to the six Tinmiaq wells, the

company planned four “rank exploration”

wells at Harpoon.

ConocoPhillips hadn’t intended to

complete all 10 wells, only to provide

options for a seven-well program. But

global circumstances made even that

smaller goal impossible.

Just as the exploration season was

gathering momentum, the coronavirus

pandemic was suspending operations

around the world, including the distant

and isolated North Slope.

By the time ConocoPhillips demobi-

lized its fleet in early April in response to

the pandemic, the company had only

completed one of the Harpoon wells —

Harpoon No. 2.

A further disappointment came earlier

this year. In its annual U.S. Security and

Exchange Commission filings,

ConocoPhillips announced that Harpoon

No. 2 had been a dry hole. According to

the company, “evaluations confirmed the

well intersected sub-commercial volumes

of hydrocarbons in the upper Harpoon

interval which will not be developed.”

In an earnings call in early 2020, Fox

said Harpoon 2 appeared to have “clipped

the edge of the topset based on its log

response,” adding that the company

wouldn’t know for sure until it drilled a

second well. Asked by analysts whether

the well had encountered hydrocarbons,

Fox acknowledged that it had. “It looks

from a lithological perspective similar to

other lithological signatures we’re seeing

PETROLEUM NEWS • WEEK OF MAY 16, 2021 5

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EXPLORERS PREVIEW

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The company planned a seven-well exploration program for

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response to the emerging coronavirus pandemic.

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on the edge of these topsets,” he said.

Even so, the company said it still

believed in the potential of the “Harpoon

Complex,” described as Harpoon, Lower

Harpoon and West Harpoon, and intended

to return to it.

Narwhal The 2018 exploration program to

appraise the Willow discovery also includ-

ed a pair of exploration wells just south of

the Colville River unit, near the village of

Nuiqsut.

The play has a long and circular history

with many names.

ConocoPhillips first asked the state to

expand the Colville River unit to include

acreage to the south in 2002, around the

time of its merger. The prospect was

known at the time as Titania. The state

agreed to the Titania expansion but eventu-

ally contracted the acreage out of the unit

in 2004 after ConocoPhillips had failed to

meet its drilling commitments.

A joint venture operated by Brooks

Range Petroleum Corp. subsequently

acquired the acreage through a lease sale

and began referring to the leases as the

Tofkat prospect. The small independent

encountered hydrocarbons on the leases in

early 2008 with the Tofkat No. 1 well and

two related sidetracks and later formed the

Tofkat unit in October 2011.

The state terminated the unit in late

March 2016, after the company missed

work commitments. The termination pro-

ceedings came as ConocoPhillips was

acquiring the acreage. ConocoPhillips

asked the state to incorporate it into the

Colville River unit.

The state was hesitant to approve the

expansion, because of the atypical status of

the leases and because of ConocoPhillips’

previous failure to explore the acreage. But

state officials ultimately agreed to the

request, pursuant to bonds, guarantees and

conditions.

Under this newest effort,

ConocoPhillips began referring to the proj-

ect as Putu. To meet the initial set of con-

ditions required by the state,

ConocoPhillips drilled the Putu No. 2 and

Putu No. 2A wells and made a $3 million

bonus bid replacement. The company also

drilled four appraisal wells — CD4-

595PH1, CD4-595, CD4-594PH1 and

CD4-594 — beyond its work commit-

ments “to better understand the reservoir

and to test the technical feasibility of

extended reach drilling at shallow depth,”

according to the company.

The next round of commitments

required ConocoPhillips to pay $4 million

to the state and submit a plan detailing

efforts to bring the leases into sustained

production.

Based on preliminary testing of its ini-

tial Putu exploration wells, the company

announced the Narwhal discovery, esti-

mated to contain between 100 million and

350 million barrels of oil equivalent. Like

Willow, Narwhal was also in the

Nanushuk formation. Willow and Narwhal

are different sediments deposits within the

formation, with Willow being older.

ConocoPhillips drilled a follow-up well

at Narwhal in the 2019 exploration season.

That summer, the company said that the

results were “encouraging” enough to jus-

tify “an additional unbudgeted horizontal

well from an existing Alpine drill site into

the Narwhal trend” later in the year. That

relatively spontaneous decision, at least by

North Slope standards, reflects one of the

big strategic opportunities of the prospect.

It is close enough to the Colville River unit

to utilize existing well pads, bringing

down costs and reducing some of the most

common logistical complications of off-

road winter exploration.

Asked about the additional well, Fox

said it would be a “long-term test” to better

“understand the long-term deliverability.”

He added, “We also can drill an offset

injection well to this producer from the

same drill site. So, we’re going to take the

opportunity to do that as well. And that

will give us further information on the

Narwhal trend. But it’s really driven by

encouragement and what we saw in the

initial well in the Narwhal, the Putu

appraisal well we call that. We’re feeling

good about that.”

A long-term flow test conducted on the

Narwhal exploration well also “exceeded

expectations,” according to

ConocoPhillips. The well produced at a

peak rate of 4,500 barrels of oil per day,

leading the company to increase its esti-

mated ultimate recovery figure for the

prospect by 150 million to 400 million bar-

rels of oil equivalent.

The company initially envisioned a

two-pronged strategy at the Narwhal

prospect. It would drill about half the wells

horizontally from the existing CD-4 pad at

the Colville River unit and the remaining

wells from a new CD-8 pad in the southern

end of the unit.

Under that proposal, the company ini-

tially expected production as early as 2022

from the wells at the CD-4 pad and pro-

duction from the planned CD-8 pad as

early as 2025.

But by late 2020, the company was

rethinking its approach. The CD4-594 and

CD4-595 appraisal wells had “stretched

the limits” of serviceable extended reach

drilling at shallow depths, according to

ConocoPhillips. And so the company shift-

ed the project toward CD-8, which would

support between 20 and 40 wells, depend-

ing on modeling.

Stony Hill As part of the 2018 program to apprais-

al Putu, ConocoPhillips also explored the

Stony Hill prospect, located in the NPR-A

about six miles south of the village of

Nuiqsut. The well and sidetrack were west

of the Armstrong Energy Inc. wildcat

Horseshoe No. 1 well.

ConocoPhillips described Stony Hill as

a prospect similar to Willow and estimated

that it contained at least 300 million barrels

of recoverable oil in the Nanushuk forma-

tion. In November 2017, ConocoPhillips

executive Matt Fox said the company had

identified “a lot” of Willow lookalikes in

the Nanushuk and “every one of them

we’ve drilled so far has had oil in it, so

we’re hopeful that several of these Willow

lookalikes will deliver.”

The Stony Hill wells encountered oil

but required additional appraisal drilling

and analysis — as did the Putu wells,

which are closer to Colville River unit

infrastructure.

All the ConocoPhillips projects at the

Colville River unit and in the NPR-A place

additional responsibilities on the Alpine

infrastructure. In his Meet Alaska presen-

tation, Isaacson described three projects

6 PETROLEUM NEWS • WEEK OF MAY 16, 2021

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underway this year to expand the gas-han-

dling capacity and power generation and to

add a slug catcher at the Alpine processing

facility. The $190 million projects would

allow Alpine to handle additional produc-

tion coming online.

Nuna Just as the Narwhal project has been

extending the reach of the Colville River

unit to the south, the Nuna project is

extending the reach of the Kuparuk River

unit to the north.

For years, the Nuna prospect was seen

as crucial to the future of the Oooguruk

unit, located in the waters of Harrison Bay

northwest of the Kuparuk River unit.

Companies in the region had known about

the prospect for years. The Nuna field is

located in the shallow Torak formation,

and all drilling into deeper reservoirs had

passed through it.

Pioneer Natural Resources Alaska Inc.

officially discovered the prospect during

the 2013 winter exploration season with its

Nuna No. 2 well. With the results that well,

the independent increased both the aerial

extent and the estimated ultimate recovery

of the field — claiming it could contain

between 75 million and 100 million barrels

of recoverable oil, resulting in some

25,000 barrels of oil per day over 25 to 30

years.

The next operator of Oooguruk, Caelus

Natural Resources Alaska Inc., sanctioned

a $1.4 billion Nuna development — with

$550 million for construction and the

remainder for drilling — in 2015 and even

received a major royalty modification

from the state to make the project work. It

paused work a few years over concerns

about the economic climate.

Caelus ultimately left Alaska in early

2019, selling off its properties. While the

company sold the Oooguruk development

to its minority partner Eni, and later

announced that it had sold 100% owner-

ship in the Nuna leases to its neighbor

ConocoPhillips.

The sale made sense considering that

the company had intended to access the

offshore Nuna leases using an onshore

development at Oliktok Point, in the

Kuparuk River unit.

ConocoPhillips had already been test-

ing wells in the Torok since at least 2013.

Speaking about the project during an earn-

ings call in July 2019, ConocoPhillips

executive Michael Hatfield said that the

Nuna prospect could be developed mostly

from existing pads and roads and that the

remaining facilities could be built in a sin-

gle ice road season. He estimated that the

field could be developed with oil prices in

the low $30 per barrel range and that the

field would produce about 100 million bar-

rels on $100 million investment.

At that time — nine months before the

pandemic — ConocoPhillips was planning

a few years of appraisal as part of it

Kuparuk River program, leading to first oil

in 2022. In his Meet Alaska presentation,

Isaacson put the timeline for first oil at the

“mid-2020s.”

Nuna production would be processed

through Kuparuk River unit facilities, as

would additional production from the

NEWS project. Although not traditional

exploration, the expansion of viscous oil

production from the 1H NEWS drill site is

a source of new oil.

Legacy ConocoPhillips’ work west of Prudhoe

Bay has influenced regional exploration.

Incremental advancement is a defining

feature of the North Slope. The basin con-

tains many known oil fields that would

instantly be standalone commercial prop-

erties if they existed in a less remote corner

of the world. The challenge on the North

Slope over the past 60 years has been

building up regional infrastructure to cre-

ate economies of scale.

By developing the Kuparuk River unit

and then the Colville River unit,

ConocoPhillips changed the characteristics

of the swath of land between those two oil

fields. The so-called “billion-dollar fair-

way” has perpetually interested smaller

exploration companies.

There are currently three units in the

region: the Oil Search-operated Pikka unit,

the Arctic Slope Regional Corp.-operated

Placer unit and the Mustang Holding LLC-

operated Southern Miluveach unit, which

was the first to move into development.

Pikka, Placer and Southern Miluveach

all, in some fashion, rely upon the infra-

structure of the Conoco-Phillips’ operated

units, usually in the form of various

pipeline capacity.

These partnerships are not perfect. In

some cases, smaller players have chosen to

pursue standalone production facilities,

rather than attempt to find space with

ConocoPhillips facilities.

Building standalone facilities greatly

alters the economics of a project. A compa-

ny would only assume the expense volun-

tarily if self-sufficiency provided an equiv-

alent benefit.

But, by comparison, the lands east of

Prudhoe Bay are much less crowded.

Geology is partially responsible for that

imbalance. The Point Thompson unit and

the neighboring Badami unit have both

proven to be exceptionally challenging

puzzles.

But history matters, too.

Point Thompson came online much

later than the Kuparuk River unit. And

whereas the Kuparuk River unit sits imme-

diately adjacent to Prudhoe Bay, Point

Thompson is some 30 miles away, creating

a much larger area to traverse through that

incremental advancement. The reopening

of the NPR-A in 1999 created incentives to

the west, while the political complications

at the Arctic National Wildlife Refuge over

the same time created disincentives to the

east.

One can imagine an alternate history: if

ANWR had been open for development, if

Point Thompson had been closer to

Prudhoe Bay, if geology had been more

accommodating, perhaps there would also

be a billion-dollar fairway to the east

instead of the west. l

PETROLEUM NEWS • WEEK OF MAY 16, 2021 7

RESOURCEBUILDING A

TRIESE INDUS’SALASKA

S

wind and solar generating capacity in

2021 and 2022 will contribute to rising

electricity generation from those

sources and estimates the U.S. electric

power sector added 14.8 gigawatts of

new wind capacity in 2020, with an

additional 15.9 GW expected to come

online in 2021 and an additional 5.2

GW in 2022.

EIA said utility-scale solar will rise

an estimated 10.5 GW in 2020 and is

forecast to grow by 15.7 GW in 2021

and by 15.9 GW in 2022, with about 5

GW of small-scale solar, systems less

than 1 megawatt, expected to come

online in 2021 and again in 2022. l

continued from page 3

EIA OUTLOOK

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EXPLORERS PREVIEW

The company employed as many as 700 people on the GMT-2

project this winter, which was the third and final year of

construction on the $1.4 billion project.

Contact Eric Lidji at [email protected]

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8 PETROLEUM NEWS • WEEK OF MAY 16, 2021

l E X P L O R A T I O N & P R O D U C T I O N

Weekly US rotary rig count up by 8 to 448 By KRISTEN NELSON

Petroleum News

The Baker Hughes U.S. rotary drilling rig count, 448

on May 7, was up by eight from 440 the previous

week and up by 74 from a count of 374 a year ago.

When the count bottomed out at 244 in mid-August

last year, it was not just the low for 2020, but the lowest

the count has been since the Houston based oilfield serv-

ices company began issuing weekly U.S. numbers in

1944.

Prior to 2020, the low was 404 rigs in May 2016. The

count peaked at 4,530 in 1981.

The count was in the low 790s at the beginning of

2020, where it remained through mid-March, when it

began to fall, dropping below what had been the historic

low in early May with a count of 374 and continuing to

drop through the third week of August when it gained

back 10 rigs.

The May 7 count includes 344 rigs targeting oil, up

by two from the previous week and up by 52 from 292 a

year ago, 103 rigs targeting gas, up by seven from the

previous week and up by 23 from 80 a year ago, and one

miscellaneous rig, down by one from the previous week

and down by one from a year ago.

Twenty-three of the holes reported May 7 were direc-

tional, 408 were horizontal and 17 were vertical.

Alaska unchanged from previous week Texas (217) was up by five rigs from the previous

week.

Louisiana (52) was up by three.

Pennsylvania (19) and Utah (9) were each up by one rig.

California (6) was down by a single rig.

Counts in all other states were unchanged from the

previous week: Alaska (3), Colorado (10), New Mexico

(70), North Dakota (15), Ohio (10), Oklahoma (21),

West Virginia (11) and Wyoming (4).

Baker Hughes shows Alaska with three rigs active

May 7, unchanged from the previous week and

unchanged from a year ago, when the state’s count also

stood at three.

The rig count in the Permian, the most active basin in

the country, was up by five from the previous week at

229 and up by 31 from a count of 198 a year ago.

International count down Baker Hughes’ April international rig count of 695,

released May 7, was down 20 rigs from March, with land

rigs down 16 to 530 and offshore rigs down four to 165.

The company said the international count is down

220 from last year’s count of 915, with land rigs down

157 and offshore rigs down 63.

The U.S. rig count for April averaged 436, up 28 from

a March average of 408 and down 130 year-over-year.

In Canada the average count for April was 58, down

51 from a March count of 108 and up 25 year-over-year.

The worldwide count, international plus U.S. and

Canada, was 1,189 in April, down 43 from a March

count of 1,231 and down 325 from 1,514 in April 2020.

The Houston based oilfield services company began

issuing weekly U.S. numbers in 1944 and began issuing

the monthly international rig count in 1975. l

its two Castle North leases; the first NPR-A acreage it plans

to drill.

Borealis’ first taker for a JV partner was Armstrong Oil

& Gas for a 72% interest in the Castle West prospect.

The reason the company decided to drill Castle North

first was because of its proximity to the U.S. Bureau of

Land Management’s Inigok Operations Center and its infra-

structure, which will reduce the costs of the exploration pro-

gram.

The Castle North winter exploration project is on the

Arctic coastal plain approximately 35 miles west of the

Colville River and 15 miles west of Judy Creek. Teshekpuk

Lake is about 30 miles to the north and the closest coastline

is some 40 miles from the project area.

The coastal area is broad and flat with numerous lakes

and waterbodies.

Inigok history The U.S. Geological Survey and Husky Oil drilled the

Inigok No. 1 well in what is today called the Castle North

prospect in 1978 and 1979. The well was subsequently

plugged and abandoned but the infrastructure for the project

remains useable and includes a large gravel pad and a year-

round, 6,500-foot gravel airstrip.

Borealis currently holds two NPR-A leases that define

the Castle North prospect (see map in the pdf and print ver-

sions of this issue of PN).

Drilling plans Drilling operations will involve two wells, Castle North

1 and Castle North 2, although the company has identified

four potential Castle North drilling sites.

Activities include mobilization, snow trail/ice road and

ice pad construction, possible well testing and demobiliza-

tion. They will initially follow the existing exploratory road

from Deadhorse to ConocoPhillips Kuparuk 2-P pad.

Beyond this point, access will require an approximate 80-

mile-long packed snow trail.

Project ice roads will be constructed from the Inigok

Operations Center to transport a drill rig and equipment to

the drill sites. The airstrip at Inigok may be used for addi-

tional access via aircraft, Borealis said.

Drilling operations will occur on a 250,000 square foot

ice pad with a surface working area of 400 feet by 400 feet,

or 160,000 square feet. The pad will support the land-based

drill rig and a small Command Center camp.

Borealis said in its application that the Doyon Arctic Fox

drill rig (or one similar) will be used.

The proposed CN 1 well site is approximately 40 miles

west of the Colville River, 50 miles southwest of Nuiqsut.

Access to the site will be via a 7.4-mile-long ice road

from the Inigok Operations Center, with rig mobilization

expected to occur in January.

Drilling, coring, setting casing, and testing are expected

to take up to 30 days. Once completed, the rig will be demo-

bilized and transported to the next drill site, CN 2, between

late-February and mid-March.

Access to the site will be via a 4.14-mile-long ice road

from the Inigok Operations Center. The rig will be demobi-

lized between mid- and late-April.

Site cleanup, closure inspections and remediation (as

needed) will take place in late-April with final post snow

stick picking and site closure by June, the company said in

its C-plan app.

Ahead of Willow According to Garrard, Nordaq (later rebranded Borealis)

recognized the potential of the Castle trend and obtained

leases in the area three years before ConocoPhillips

announced its big Willow oil discovery.

Borealis said it will use Alaska Chadux as the primary

response action contractor and the IC contractor Witt-

O’Brien’s will provide the primary support for staffing the

incident command team.

Contractors in Deadhorse or Prudhoe Bay may be used

for logistics or other support. l

N A T I O N A L P E T R O L E U M R E S E R V E - A L A S K A ( N P R A ) Nuiqsut

Prudhoe Bay

DS-2P

Inigok

K

NAD 1983 StatePlane Alaska 5 FIPS 5005 Feet

Figure:0 20 4010 Miles

CN 02

CN 04

CN 01CN 03

Delineated Water Source

Delineated Ice Road

Staked Well Pad

Pack Snow Winter Trail

Borealis BLM NPRA Lease

National Petroleum Reserve - Alaska (NPRA) 0 30 6015 Km0.1-1

Beaufort Sea

B E A U F O R T S E A

AA084158AA084157

Oil Discharge Prevention and Cont ingency Plan

BOREALIS ALASKA OIL, INC.CASTLE NORTH

PROSPECT LOCATION MAP

continued from page 1

BOREALIS PERMITTING

Page 9: PIPELINES & DOWNSTREAM Alyeska cyber-aware

PETROLEUM NEWS • WEEK OF MAY 16, 2021 9

Oil Patch Bits

ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS

Companies involved in Alaska’s oil and gas industry

A Acuren . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3 AES Electric Supply, Inc Afognak Leasing LLC Ahtna, Inc. Airport Equipment Rentals . . . . . . . . . . . . . . . . . . . . . . . . . .5 Alaska Dreams Alaska Frontier Constructors (AFC) Alaska Fuel Services Alaska Marine Lines Alaska Materials Alaska Railroad Alaska Steel Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4 Alaska Textiles Alaska West Express Arctic Controls ARCTOS Alaska, Division of NORTECH . . . . . . . . . . . . . . . . .6 Armstrong ASTAC (Arctic Slope Telephone Assn. Coop, Inc) AT&T Avalon Development

B-F Bombay Deluxe BrandSafway Services Brooks Range Supply C & R Pipe and Steel Calista Corp. Caltagirone Legal, LLC ChampionX Coffman Engineers Colville Inc. Computing Alternatives

CONAM Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7 Cook Inlet Tug & Barge Cruz Construction Denali Universal Services (DUS) Doyon Anvil Doyon Associated Doyon Drilling Doyon, Limited EEIS Consulting Engineers, Inc. EXP Energy Services F. R. Bell & Associates, Inc. Flowline Alaska Frost Engineering Service Co. – NW Fugro

G-M GCI GMW Fire Protection Greer Tank & Welding Guess & Rudd, PC HDR Engineering, Inc. ICE Services, Inc. Inlet Energy Inspirations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10 Judy Patrick Photography Little Red Services, Inc. (LRS) Lounsbury & Associates Lynden Air Cargo Lynden Air Freight Lynden Inc. Lynden International Lynden Logistics Lynden Transport Maritime Helicopters

N-P Nabors Alaska Drilling NANA Worley . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2 Nature Conservancy, The . . . . . . . . . . . . . . . . . . . . . . . . . . .12 NEI Fluid Technology Nordic Calista North Slope Borough North Slope Telecom Northern Air Cargo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3 Northern Solutions NRC Alaska, a US Ecology Co. Oil Search PND Engineers, Inc. PRA (Petrotechnical Resources of Alaska) Price Gregory International

Q-Z

Raven Alaska – Jon Adler Resource Development Council SALA Remote Medics SeaTac Marine Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7 Security Aviation Shoreside Petroleum Soloy Helicopters Sourdough Express Strategic Action Associates Tanks-A-Lot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4 Weston Solutions Wolfpack Land Co. Yukon Fire Protection

All of the companies listed above advertise on a regular basis with Petroleum News

Lynden cats make tracks on the Slope As reported by Lynden News May 5, Lynden Oilfield

Services’ fleet of three PistenBully snowcats have been hard at work in Prudhoe Bay this past winter. In an aver-age week, the cats delivered essential supplies to a remote drilling site 145 miles southwest of Deadhorse and hauled a propane truck to refill two remote tanks used to power a weather station. Operators Tony Warner, Joel Martens, James McSharry and Hunter Keogh operate the machines in severe conditions to serve Lynden customers. They received instruction in freight operations and survival as part of their preparation to operate the machines in extreme weather. The PistenBullys give Lynden customers over-snow options to move their cargo including heavy equipment, containers and camps.

CO

URT

ESY

LY

ND

EN

to ensuring adequate safety and environmental protec-

tions for this sensitive ecosystem and Alaska Native sub-

sistence activities.”

Moriarty, president and CEO of the Alaska Oil and Gas

Association, disagreed.

“The 2016 Arctic drilling rule was revised because

much has been learned about operating safely in the Arctic

over the last five years. The 2020 proposed revisions

made substantial improvements over the original rule,

including revisions to incorporate new technologies and

modern drilling practices,” she explained.

“The 2020 rulemaking process also included additional

input from tribal leaders, Alaska Native corporations, and

other stakeholders.”

Interior’s decision “means those enhanced safety and

environmental updates go away, and terms of the 2016

rule remain in place. Ironically, this decision does not ben-

efit the environment as much as the 2020 rule. It is unfor-

tunate that politics have taken over what should have been

a purely scientific exercise,” Moriarty said.

Leah Donahey, Alaska Wilderness League legislative

director, said the 2016 rules incorporated lessons learned

from the 2010 Deepwater Horizon oil spill in the Gulf of

Mexico.

She also said there has not been a public push by com-

panies showing interest in the offshore.

Conservation group Oceana said 37 exploratory wells

have been drilled in the Beaufort and Chukchi seas since

the 1970s; many on leases that have since expired.

Weighed in Russian interest The changes proposed by the Trump administration

were not finalized before Joe Biden was inaugurated. In

November 2020 Interior said the purpose of the proposed

revisions was “to remove unnecessary, burdensome provi-

sions while ensuring that energy exploration on the Arctic

Outer Continental Shelf remains safe and environmentally

responsible.”

“As countries like Russia increase their presence in the

Arctic — including the use of U.S. technologies to devel-

op their seabed resources, it is increasingly important to

ensure that the United States has a strong presence in the

Arctic OCS,” said then-Deputy Secretary of the Interior

Kate MacGregor. “The Beaufort and Chukchi Seas have a

long legacy of oil and gas development — we believe

these proposed revisions will better harness new techno-

logical innovation and best science to allow for responsi-

ble domestic energy development off the coast of Alaska.”

Executive Order 13795, issued by Donald Trump in

2017, directed Interior to review the 2016 Arctic

Exploratory and Drilling Rule and report recommenda-

tions. Interior said the revision team included career sub-

ject matter experts and regulatory specialists who looked

to additional research in the review, including a Bureau of

Safety and Environmental Enforcement-commissioned

technology assessment program study, National

Petroleum Council reports and consultations with “leaders

of more than 23 Alaska Native tribes, Alaska Native

Claims Settlement Act corporations and municipalities

throughout Alaska.”

The Federal Register notice issued for the 2020 revi-

sions said the 2016 rule was a response to BSEE- and

Bureau of Ocean Energy Management-initiated environ-

mental and safety reviews based on experience in the

Arctic OCS “gained from Shell’s 2012 and 2015 Arctic

operations.”

The notice also said the 2016 rule was “narrowly

focused, applying solely to exploratory drilling operations

conducted during the Arctic OCS open-water drilling sea-

son by drilling vessels and ‘jack-up rigs’ in the Beaufort

Sea and Chukchi Sea Planning Areas.”

The BSEE and BOEM review of the 2016 rule takes

into account a congressional declaration in the Outer

Continental Shelf Lands Act that policies and procedures

for managing oil and gas development in the OCS be

“intended to result in expedited exploration and develop-

ment of the Outer Continental Shelf in order to achieve

national economic and energy policy goals, assure nation-

al security, reduce dependence on foreign sources, and

maintain a favorable balance of payments in world trade.”

The bureaus also reviewed new information on techno-

logical developments in an ice environment.

—KAY CASHMAN

(the Associated Press contributed to this story)

continued from page 1

DRILLING RULES“The 2020 rulemaking process also included additional input from tribal leaders, Alaska

Native corporations, and other stakeholders.” —Kara Moriarty

Call 907-250-9769 for details

Page 10: PIPELINES & DOWNSTREAM Alyeska cyber-aware

10 PETROLEUM NEWS • WEEK OF MAY 16, 2021

4011 W. Arctic Blvd., Suite 101 • Anchorage, Alaska

229-6000

the U.S. East Coast.

Colonial is the largest pipeline system for refined oil

products in the United States, capable of moving 3 million

barrels of fuel per day between Texas and New York —

45% of the fuel consumed on the Eastern Seaboard between

the Gulf Coast and the New York metro area.

The snafu, induced by Russia-based hackers, engen-

dered lines of cars as panicked East Coast motorists binged

on whatever fuel supplies could be found at the local gas

station.

“As for this Colonial event, we are paying attention

through trade associations; through government agencies;

through law enforcement; to know what we can learn from

this,” Egan said, adding, “I mean the continually evolving

themes that our team works hard to stay on top of.”

Alyeska is poised to learn whatever it can learn from the

breach, and any other real-world cybercrime that may

plague pipelines and other critical infrastructure, Egan said.

“We learn things and change things because that’s part of

this world of cybersecurity, it’s continually moving … a

very dynamic area,” she said. “I can guarantee that we will

be making changes, but our system is very comprehensive,

and it has served us well.”

Asked about system redundancy, Egan said Alyeska has

multiple layers of protection against cyber threats.

Waivers The Biden Administration began what it called an “all of

government” effort to address the pipeline interruption. It

initiated a survey of Jones Act-qualified vessels to begin the

process of evaluating what assets are available in the Jones

Act fleet to carry petroleum products within the Gulf, and

from the Gulf up the Eastern Seaboard, it said in a May 11

White House fact sheet.

The U.S. Maritime Administration was asked to deter-

mine if there is sufficient capacity on Jones Act-qualified

vessels to carry needed fuel and to determine if a waiver is

warranted, the White House said, adding, “Authority to

receive requests for and to approve waivers to the Jones Act

belongs to the Department of Homeland Security.”

The administration also issued a “targeted, one-week

waiver” allowing multiple states to temporarily use non-

compliant fuel to boost available supply. EPA Administrator

Michael Reagan temporarily waived the federal Reid vapor

pressure requirements for fuel sold in reformulated gasoline

areas of District of Columbia, Maryland, Pennsylvania and

Virginia. The waiver was later extended to a total of 12

affected states, and it was extended to May 31.

“The EPA stands ready to issue waivers for other affect-

ed states expeditiously whenever those requests are

received,” the White House said.

The Department of Transportation issued a separate

order allowing trucks to carry overweight loads of gasoline

and other fuels on highways to move more supply to

Colonial’s customers. It also issued a temporary hours of

service exemption which applies to truckers transporting

gasoline, diesel, jet fuel and other refined petroleum prod-

ucts to the region.

The DOT Federal Motor Carrier Safety Administration

will work closely with its state and industry partners to

monitor driver work hours and conditions for the duration

of the exemption, DOT said.

Colonial said it had, “consistent with our safety policies

and regulatory requirements,” increased aerial patrols of the

pipeline right of way and that it had deployed more than 50

personnel to walk and drive the pipeline each day.

A ransomware group, DarkSide, demanded a cryptocur-

rency ransom valued at millions of dollars, according to

several sources, CNN reported May 12.

But Colonial may not pay up, the report said. Working

with U.S. government officials, Colonial has managed to

retrieve the most important data that was stolen, according

to a source.

“We would like to thank the White House for their lead-

ership and collaboration in resolving this matter as well as

the DOE, PHMSA, FERC and other federal agencies for

their ongoing support,” Colonial said in a May 11 state-

ment.

IBM’s new CEO Arvind Krishna suggested a NASA-

style government investment is required to be able to tackle

cybersecurity.

“When we talk about infrastructure, you talk about the

Colonial Pipeline — that’s physical infrastructure; if the

cyber side gets attacked, the physical is useless,” Krishna

told First Move. “When we talk about infrastructure, we

should make sure the cyber is on equal stage and equal foot-

ing with the physical.”

Krishna called for spending $100 billion on a public/pri-

vate partnership to improve cyber resilience.

“Otherwise, we’ll be victim to these attacks again and

again,” he said.

100% reliability in 2020 Egan said Alyeska achieved 100% TAPS reliability in

2020.

“I think it’s important for people to know that we —

everyone who works here at Alyeska understands how

much the state of Alaska relies on us to be operate reliably,

she said. “We understand how important that is and that’s

why we have such a robust system.”

The first line of defense is people, Egan said.

“People who work here are very connected to TAPS

itself, and take a lot of pride in its operation,” she said.

“We do have drills and exercises, much as we do for

other risks such as oil spills,” she said. “We do test our sys-

tem and then we also test our response, with drills and exer-

cises.”

“We spend a lor of time in our company making sure that

all of our employees and contractors are engaged in and

educated about cybersecurity threat — the ones that you

face at home, the ones that every business faces,” Egan said.

“We also have a very active program in keeping our

employees aware of what they can do to protect themselves,

things like phishing and malware, etcetera.”

Alyeska said 2020 was the first time it had hit the 100%

reliability level since 2003, but that the score is traditionally

above 90%.

“The pipeline is operating reliably throughout this event

with Colonial, and so is our business side of our house,” she

said.

“When we end up in the upper 90s, it’s usually because

of a planned shutdown, and the duration of that shutdown,”

Egan said. “It’s typically not anything concerning, but

some downtime that we planned for in order to get work

done.”

Basically 100% reliability means “every barrel that we

receive we deliver,” Egan said.

“To get down to the nuts and bolts of that and how we

did that last year, we were able to make our maintenance

shutdown several short ones, instead of longer ones,” she

said. “While we might shut down for 12 hours, we use the

tanks at Pump Station 1 to take in incoming crude and when

that shutdown is over, we start moving oil again, so there’s

really no impact on the downstream side.” l

continued from page 1

CYBER-AWARE

Despite a growing string of rebuffs from British

Columbia and federal courts, the threats to TMX have

ranged from COVID-19, rail blockades and legal chal-

lenges to … hummingbirds!

The 3-inch-long birds, whose annual migratory flights

cover round trips of almost 4,000 miles, did what few others

outside of high court rulings have managed to do —

stopped construction of the pipeline through a forest in the

Greater Vancouver region until Aug. 20.

Environment and Climate Change Canada, a federal

department, issued an order in in April covering a strip of

1,100 yards until the end of the bird nesting season.

“Given that it is nesting season, migratory birds are par-

ticularly vulnerable at this time,” the department said, after

two on-site inspections.

“Cutting vegetation and trees or carrying out other dis-

ruptive activities such as bulldozing or using chainsaws in

the vicinity of active nests will likely result in disturbance

or destruction of those nests.”

Trans Mountain, owned by the Canadian government,

confirmed the order without comment.

Insurer issue On a much larger scale, Trans Mountain has been caught

up in a bid by environmentalists to disclose its insurers,

hoping that would provide fresh targets for activists.

That strategy has been spurred by a decision in April by

Zurich, the giant Swiss-based company, not to renew its

coverage of what opponents call a “climate wrecking”

pipeline from the oil sands.

A spokesman for Zurich said the insurer will not com-

ment on its customer dealings.

Trans Mountain said it has the insurance it needs for its

existing operations and the “expansion project” covering

claims up to C$508 million.

Zurich was the sole insurer for the first C$8 million of

potential payouts, along with C$300 million of cover with

other partners.

Lloyd’s of London syndicates are Trans Mountain’s

biggest insurer, with packages that involve 11 companies,

of whom Germany’s Talanx/Hannover indicated last year it

planned to drop its participation in the pipeline, while the

Munich group said it would review its contract given its

new underwriting guideline for the oil sands.

Confidentiality issue As that pressure builds, Trans Mountain gained the

continued from page 1

PIPELINE EXPANSION

see PIPELINE EXPANSION page 11

Contact Steve Sutherlin at [email protected]

Page 11: PIPELINES & DOWNSTREAM Alyeska cyber-aware

PETROLEUM NEWS • WEEK OF MAY 16, 2021 11

Pacific Oil & Gas President Ratnesh Bedi said BP is

among the companies turning to LNG for “sustainable,

stable gas that will supply a clean energy mix” at a time

when the outlook for LNG faces uncertainty.

Work pauses as demand grows In just the last two months, LNG developer Annova

stopped work on its export plant in Brownsville, Texas,

and Pembina Pipeline paused development of its Jordan

Cove project in Oregon.

On the positive side, global LNG demand has

increased every year since 2012, propelled by fast-rising

demand in Asia.

But global LNG buyers have shown some hesitancy

in recent times due to overbuilding of export terminals in

2019 and demand destruction resulting from COVID-19.

BC finances hereditary chiefs While these fluctuations persist, the British

Columbia government has added to the confusion by

financing Wet’suwet’en hereditary chiefs in northwest-

ern B.C. who have tried to sink plans for the C$40 bil-

lion LNG Canada project.

The government of Premier John Horgan has grant-

ed C$7.2 million to the chiefs to promote “unity” in the

fractured First Nation divided between elected and

hereditary leaders, with the bulk of the elected commu-

nities counting on benefits agreements they have

signed with the Shell-operated project.

“British Columbia’s funding announcement to

‘unify’ the Wet’suwet’en nation is the latest in a year-

long series of insults and betrayals of the elected repre-

sentatives of the Wet’suwet’en people,” declared one of

the elected chiefs from five clans Maureen Luggi and

two councilors.

“For nearly a year the (Canadian and B.C. govern-

ments) and the recipients of this funding have been

negotiating in absolute secrecy about communal abo-

riginal rights and title of the Wet’suwet’en people,”

they said.

“We are being removed from any meaningful partic-

ipation in the future of our territory. Despite every

appeal to right and reason, the province has handed

C$7.2 million to an unelected, unrepresentative,

unmandated, unaccountable society to continue their

secret negotiations.”

Some of the new funding will be used to convert

(recently acquired school property) into a

Wet’suwet’en governance center, which is expected to

be a focal point in what the B.C. government says will

allow the divided First Nation to “resolve their own

matters that is central to self-determination.”

This latest twist in a bitter dispute further compli-

cates the outlook for TC Energy’s Coastal GasLink

pipeline to deliver natural gas feedstock to the LNG

Canada liquefaction plant and tanker terminal.

That construction was brought to a halt 16 months

ago by supporters of the hereditary chiefs, when they

blockaded one of Canada’s two main rail lines to the

Pacific Coast, costing governments and companies

hundreds of millions of dollars in lost business. l

continued from page 1

WOODFIBRE LNG

The company told FERC that tidal currents at Turn Point

are known to be powerful and cited an Alaska Power

Authority report from 1981 titled “Angoon Tidal Power and

Comparative Analysis,” which looked at power generation

options which would allow the City of Angoon to replace

on-site diesel generators. Generating electricity from tidal

power in Kootznahoo Inlet was one of the options consid-

ered, but, due to the location’s remoteness, LPS said, “more

accurate assessments of the tidal power resource are not

available.”

“The project concept would be to generate electric

power from a marine hydrokinetic device and store power

in an energy storage system to be used by the City of

Angoon as a supplement to other energy sources,” LPS

said.

The company said a turbine or combination of turbines

generating 300 kilowatts would be appropriate based on

existing power demand in Angoon and allowing for some

growth. Such a turbine would produce some 600-megawatt

hours of electricity in a year.

There would be distribution cables fastened to the

seabed between the turbine generator and the landfall loca-

tion and an energy storage system which would likely

include state-of-the art battery storage technology such as

lithium-ion systems currently used for grid electricity stor-

age.

LPS said it expects that two cables would be installed,

one for primary use and the other for redundancy.

Preliminary studies for the project are estimated at

$50,000.

LPS said lands on Admiralty Island which adjoin the

project area are part of the Kootznoowoo Wilderness. The

company said the project would have no impact on the

wilderness area.

Proposed project In its notice of preliminary permit application FERC said

the proposed project would include:

•A partially buoyant submersed tidal current energy con-

verter with a 3-foot-diameter rotor tethered to an anchor

post driven into the seabed in Kootznahoo Inlet;

•A dual electric cable, each with a capacity of 13.2 kilo-

watts, connecting to on-land storage; and

•On-land storage in the City of Angoon consisting of

individual lithium-ion battery cells.

The application was prepared for LPS by Barrett Energy

Resources Group, which said in a technical memorandum

to FERC that the location of the partially buoyant sub-

merged tidal current energy converter, CEC, would be

marked by a U.S. Coast Guard-approved floating buoy. The

tether would allow the CEC to move with tidal currents to

capture both ebb and flow conditions.

FERC said the project would not connect directly to the

Angoon electric system. The on-land storage system would

have a capacity of 250 kilowatts, FERC said, with annual

average generation not yet determined.

FERC is accepting comments on the permit application

for 60 days from the March 17 application acceptance.

Turnagain Arm project FERC has also accepted a preliminary permit applica-

tion for another, and much larger, Alaska project, the

Turnagain Arm Tidal Electric Generation Project (see story

in March 21 issue of Petroleum News). That application

was accepted on April 28, with a 60-day comment period.

FERC said the proposed project would consist of:

•Six 0.5-mile-long, 300-foot-wide tidal power stations,

five stations containing 40 10-megawatt tidal-to-electrical

energy generating units and one station containing 42 10-

MW tidal-to-electrical energy units; total installed capacity

of 2,420 MW;

•A transmission network of 29.81 miles of undersea

transmission lines connecting the six power stations and

coming onshore at Point Campbell in Anchorage and near

Possession Point on Kenai Peninsula Borough land;

•A 7.5-mile-long aboveground transmission line from

Point Campbell to a control building and step-up facility in

South Anchorage;

•A 2.91-mile-long, 130-kilovolt aboveground transmis-

sion line from the Anchorage control building to a 40,000-

square-foot industrial battery array with a storage capacity

of 300 MW and then to the Chugach Electric Association

substation in Anchorage;

•A 0.2-mile-long, 230 kV aboveground transmission line

from the control building to a 200,000-square-foot hydro-

gen electrolysis plant and storage yard in South Anchorage

with a processing capacity of up to 1.2-gigawatts;

•A 34.8-mile aboveground transmission line from Point

Possession to a control building and step-up facility in

Nikiski;

•A 2.75-mile-long, 230 kV aboveground transmission

line from the Nikiski control building to the Homer Electric

Association substation; and

•Appurtenant facilities.

The proposed project would have an estimated average

annual general of 10,599,500 megawatt hours.

—KRISTEN NELSON

continued from page 1

ANGOON TIDAL

support of the Canada Energy Regulator to

keep its insurers’ names confidential.

The federal agency said Trans Mountain

had “satisfied the requirements for confi-

dentiality. The names of Trans Mountain’s

insurers could reasonably be expected to

prejudice its competitive position in its deal-

ing with potential insurers.”

Charlene Alecks, a spokesperson for the

Tsleil-Waututh Nation Sacred Trust

Initiative, one of the Indigenous opponents

of the pipeline, said the CER is “expanding

Trans Mountain’s culture of secrecy when it

should be doing the opposite, especially for

a government-owned company during a cli-

mate crisis. This is a dangerous precedent.”

Grand Chief Stewart Phillip, president of

the Union of British Columbia Indian

Chiefs, said any company insuring Trans

Mountain is “complicit in violations of

Indigenous rights, because the proposed

pipeline expansion does not have the con-

sent of all impacted First Nations along the

route.”

Elana Sulakshana, energy finance cam-

paigner for Rainforest Action Network, said

Zurich’s action “demonstrates that it is wak-

ing up to the risks of this toxic project in

Indigenous land rights, local ecosystems

and the planet.”

She said some of Zurich’s peers in the

global insurance industry “are also taking

note, as eight (of the 11 companies) now

have policies that limit or end insurance

coverage (for the oil sands).”

The opponents of the pipeline are now

calling on the insurers to turn down invita-

tions to renew their coverage; rule out insur-

ance for all oil sands extraction and trans-

portation; and adopt policies to ensure that

projects and companies they insure have

obtained the full, informed consent of

impacted communities.

Financial impact Further stoking the fires of opposition,

Simon Fraser University in the Greater

Vancouver region issued a new benefit-cost

analysis study estimating Canada stands to

lose between C$3.2 billion and C$18.45 bil-

lion from the pipeline expansion.

University researchers examined close

to 20 business scenarios involving sales of

TMX crude and concluded than none will

generate a net benefit for Canada, pointing

to the prospects of increased construction

costs, the effects of weaker oil prices,

Canada’s new climate plan and the cancel-

lation of Keystone XL permits by President

Joe Biden.

Lead author and an SFU professor,

Thomas Gunton, said climate policies have

affected the landscape significantly since

the Canadian government bought Trans

Mountain off Kinder Morgan for C$4.5 bil-

lion in 2018.

The study said the crux of the problems

facing Trans Mountain is oil demand, which

it claimed will decline over coming years

because of global policy shifts toward net-

zero greenhouse gas emission goals, con-

trary to many predictions that consumption

of fossil fuels will remain strong until at

least 2050.

—GARY PARK

continued from page 10

PIPELINE EXPANSION

To advertise in Petroleum News, contact Susan Crane

at 907.250.9769petroleumnews.com

Page 12: PIPELINES & DOWNSTREAM Alyeska cyber-aware

In preparation for the system restart,

Colonial Pipeline has taken delivery of an

additional 2 million barrels of fuel from

refineries for deployment upon restart, the

company said in a May 11 situation update.

ANS fell behind Brent May 10 in the

race to $70, plunging $1.41 to $67 after

closing 12 cents above Brent on May 7.

Brent edged up May 10 by 4 cents to

$68.32, while WTI rose 2 cents to $64.92.

All three of the indexes moved modestly

higher on May 11.

U.S. crude exports fell for the week end-

ing May 7 to 1.8 million barrels per day, the

lowest level since October 2018, while

crude inventories were 0.4 million barrels

lower, according to the U.S. Energy

Information Administration.

The combination of lower exports and a

crude draw is considered by analysts to be

bullish for prices.

Demand to outstrip supply Demand levels that outstrip supply in the

second half of 2021 may pull oil prices

higher.

Under the current Organization of the

Oil Exporting Countries production sce-

nario, supplies won’t rise fast enough to

keep pace with expected demand recovery,

the International Energy Agency said in its

May Oil Market Report.

As vaccination rates rise and mobility

restrictions ease, global oil demand is set to

soar from 93.1 million bpd in first quarter

2021 to 99.6 million bpd by year-end, the

IEA said.

Weaker-than-expected first quarter oil

use in the United States and Europe and a

reduced outlook for India due to its

COVID-19 surge led the agency cut its out-

look for 2021 demand growth to 5.4 million

bpd, 270,000 bpd lower than in its previous

report.

The forecast for the second half is large-

ly unchanged on the assumption that the sit-

uation in India and elsewhere improves, the

IEA said.

World oil supply rose 330,000 bpd to

93.4 million bpd in April and will increase

further in May as OPEC+ continues to ease

output cuts, the agency said. Based on the

current OPEC+ agreement, global oil pro-

duction is set to grow by 3.8 million bpd

from April to December.

For 2021, world oil production is set to

rise by 1.4 million bpd year-on-year versus

a collapse of 6.6 million bpd in 2020, the

IEA said.

Canada leads non-OPEC+ producers

with growth of 340,000 bpd while the US is

set to contract by an additional 160,000 bpd,

it said.

The IEA revised its estimates of 2021

global refinery throughput on demand

downgrades, newly announced temporary

and permanent shutdowns, and in anticipa-

tion of a strong hurricane season in the

United States.

“As downward revisions mostly affected

2Q21, we maintain our forecast of a strong

ramp-up in refining activity in the next four

months, with refinery runs expected to peak

in August,” the IEA said, adding that after a

7.4 million bpd decline in 2020, refinery

intake is expected to increase by 4 million

bpd in 2021.

OPEC cautiously optimistic for 2nd half The global economic recovery seems to

be gaining momentum at a diverging pace

OPEC said in its Monthly Oil Market

Report for May.

“Those economies that are able to grad-

ually contain the pandemic, thanks to vacci-

nation campaigns and other successful con-

tainment strategies, and that also have the

financial capabilities to provide economic

stimulus measures are rebounding quickly,”

the cartel said.

OPEC expects most of the global recov-

ery to materialize later in the year, but it

cautioned that there are still some signifi-

cant uncertainties.

“The path of the COVID-19 pandemic

will be the overarching factor impacting the

near-term pace of the recovery, with the

potential emergence of further harmful

COVID-19 variants posing a particular

risk,” OPEC said. “Moreover, sovereign

debt in most economies has risen to levels at

which a lift in interest rates could cause

severe fiscal strain.”

A further rise in inflation, especially in

the United States and the Euro-zone, may

cause some tightening of monetary policies,

which will need to be watched in the short

term, OPEC said, adding that trade-related

disputes, especially between the U.S. and

China, may continue.

For 2021, OPEC expects world oil

demand is to increase by 6.0 million bpd,

unchanged from last month’s estimate, to

average 96.5 million bpd.

—STEVE SUTHERLIN

continued from page 1

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